Coil tubing guide

ABSTRACT

A guide system includes a flexible pipe and a plurality of bend restrictor members disposed along the flexible pipe. The bend restrictor members define a first channel and are operable to limit a degree of bending present in the first channel. An apparatus for interfacing with a subsea well includes a flexible pipe extending from a surface vessel to the subsea well. A plurality of bend restrictor members is disposed along the flexible pipe and defines a first channel. The bend restrictor members are operable to limit a degree of bending present in the first channel. Coil tubing extends from the surface vessel to the subsea well through the first channel.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

BACKGROUND

The disclosed subject matter relates generally to field of subsea oil and gas production and, more particularly, to a coil tubing guide.

Offshore oil and gas wells may generally be divided into two groups—surface piercing wells and subsea wells. Surface piercing wells are wells that are located on an artificial surface above sea level that is supported by a fixed structure (e.g., a floating platform) or a floating structure (e.g., a spar, a semi-submersible, a tension leg platform, a vessel, a barge, etc.). Subsea wells reside on the sea floor, including their wellhead structure and valving control (subsea Christmas tree).

Often during the life of a well, intervention into the well bore may be required for a variety of reasons. For example, an intervention may be required to diagnose a problem, correct a problem, stimulate production, and/or repair equipment within the well bore. Performing intervention operations on surface piercing wells is very straightforward as surface piercing wells are easily accessed through the top of the Christmas tree (located on the artificial surface) using traditional means developed for land-based wells, e.g., a lubricator, pressure containment assembly (wireline rams), and one or more lifting devices. Such operations can be performed at a relatively low cost due to the ready accessibility to the top of the Christmas tree on such surface piercing wells and the equipment used in performing such interventions.

However, intervention on subsea wells is much more difficult and expensive. Intervention of a subsea well frequently requires the rental and use of a surface vessel, a completion/workover riser, both surface and subsea pressure containment assemblies (i.e., a surface tree that mimics a surface piercing Christmas tree—so that workover hardware can be attached), and a lower workover riser package. The lower workover riser package includes a lower riser package with actuated pressure containment rams and an emergency disconnect package for well control to allow surface access to the subsea Christmas tree. Equipment used in such subsea intervention projects may not be readily available and they are much more expensive than their land-based counterparts. Moreover, intervention on a subsea well is much more complex and involved as compared to intervention projects on surface piercing wells. Thus, intervention on subsea wells may be delayed or not performed at all, or the subsea wells may simply be allowed to operate inefficiently.

So-called light well intervention was initially introduced in the North Sea in an effort to increase accessibility and reduce the costs associated with intervention of a subsea well. Generally, lightweight well intervention involves the use of a relatively small work vessel with moderate lifting capacity to go to the offshore site and lower a lightweight intervention package (LIP) on guidelines down to a subsea tree that is coupled to a well at the sea floor. Then a simple “wireline” intervention via a subsea lubricator is used to enter the well. The subsea version is an adaptation of the traditional equipment used on surface piercing wells. However, lightweight wireline work only addresses 60-70% of the types of well intervention missions oil companies are interested in employing. For the remaining 30%, oil companies rely on coil tubing (CT) intervention.

Coil tubing operation is a unique intervention method because it introduces a continuous hollow tube as the intervention string which can provide fluids, pressure, and circulation capabilities that wireline intervention methods cannot. As a result, coil tubing operations require a circulation return line of some sort to complete the hydraulic circuit as fluids are sent down the coil tubing. Usually the return fluid is captured and transmitted via the completion workover riser made from alloy steel pipe (i.e., threaded or clamped together—much like drill pipe), or more exotically, via a concentric tube made from a composite or flexible pipe, or third, by placing the reel containing the coil tubing on the sea floor near the subsea well.

The weight of the completion workover riser and the weight of its concentric outer tube causes a technical issue for smaller vessels associated with light well intervention. These smaller ship-shaped vessels have minimal draft displacement to apply sufficient tension on the top of the riser tube to keep it structurally stable in the water column and limited deck capacity to accommodate the amount of riser tube necessary, along with the coil tubing reels and surface equipment. The tension and deck load problems are exacerbated as water depth increases and environments grow more severe.

Another issue with conventional coil tubing implementations using concentric risers arises due to movement of the coil tubing. As the coil tubing moves into or out of a concentric conduit (e.g., riser or concentric tube) it tends to carry the return fluid in the direction the coil tubing is moving (i.e., into or out of the well). This tends to build up a lower pressure in the return fluid at the top end of the riser and a higher pressure at the bottom or delivery end of the riser. The imbalanced pressures at either end increase as the velocity of the coil tubing movement increases. During rapid deployment or retrieval (i.e., to save trip time) the higher imbalanced pressure may cause seal degradation at the point where the coil tubing is snubbing into the well.

This section of this document is intended to introduce various aspects of art that may be related to various aspects of the disclosed subject matter described and/or claimed below. This section provides background information to facilitate a better understanding of the various aspects of the disclosed subject matter. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art. The disclosed subject matter is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

BRIEF SUMMARY

The following presents a simplified summary of the disclosed subject matter in order to provide a basic understanding of some aspects of the disclosed subject matter. This summary is not an exhaustive overview of the disclosed subject matter. It is not intended to identify key or critical elements of the disclosed subject matter or to delineate the scope of the disclosed subject matter. Its sole purpose is to present some concepts in a simplified form as a prelude to the more detailed description that is discussed later.

One aspect of the disclosed subject matter is seen in a guide system. The guide system includes a flexible pipe and a plurality of bend restrictor members disposed along the flexible pipe. The bend restrictor members define a first channel and are operable to limit a degree of bending present in the first channel.

Another aspect of the disclosed subject matter is seen an apparatus for interfacing with a subsea well. The apparatus includes a flexible pipe extending from a surface vessel to the subsea well. A plurality of bend restrictor members is disposed along the flexible pipe and defines a first channel. The bend restrictor members are operable to limit a degree of bending present in the first channel. Coil tubing extends from the surface vessel to the subsea well through the first channel.

Yet another aspect of the disclosed subject matter is seen in a method for interfacing with a subsea well. The method includes providing a plurality of bend restrictor members disposed along a flexible pipe and defining a first channel. The bend restrictor members are operable to limit a degree of bending present in the first channel. The flexible pipe is attached to the subsea well. Coil tubing is inserted from a surface vessel to the subsea well through the first channel to interface with the subsea well.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

The disclosed subject matter will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and:

FIG. 1 is a simplified diagram of a subsea hydrocarbon production system including a coil tubing guide in accordance with one aspect of the present subject matter;

FIGS. 2 and 3 are side and cross section views of bend restrictor members in the coil tubing guide of FIG. 1, respectively; and

FIG. 4 is a diagram of a light intervention package in the system of FIG. 1.

While the disclosed subject matter is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the disclosed subject matter to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosed subject matter as defined by the appended claims.

DETAILED DESCRIPTION

One or more specific embodiments of the disclosed subject matter will be described below. It is specifically intended that the disclosed subject matter not be limited to the embodiments and illustrations contained herein, but include modified forms of those embodiments including portions of the embodiments and combinations of elements of different embodiments as come within the scope of the following claims. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. Nothing in this application is considered critical or essential to the disclosed subject matter unless explicitly indicated as being “critical” or “essential.”

The disclosed subject matter will now be described with reference to the attached figures. Various structures, systems and devices are schematically depicted in the drawings for purposes of explanation only and so as to not obscure the disclosed subject matter with details that are well known to those skilled in the art. Nevertheless, the attached drawings are included to describe and explain illustrative examples of the disclosed subject matter. The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended to be implied by consistent usage of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than that understood by skilled artisans, such a special definition will be expressly set forth in the specification in a definitional manner that directly and unequivocally provides the special definition for the term or phrase.

Referring now to the drawings wherein like reference numbers correspond to similar components throughout the several views and, specifically, referring to FIG. 1, the disclosed subject matter shall be described in the context of a subsea hydrocarbon production system 100. An illustrative subsea well 110 is positioned adjacent a sea floor 115. A subsea Christmas tree 120 is operatively coupled to the well 110 using known techniques. A lightweight intervention package (LIP) 125 is operatively coupled to the Christmas tree 120 using known techniques and methods.

In the illustrated embodiment, the LIP 125 includes a guide member 130, a snubbing injecting unit 135, and a lower riser package (LRP) 138. The LRP 138 may include interface equipment to allow interacting with the well 110 through a production access bore, such as wire cutting/sealing valves (or other sealing devices), crossover/circulation valves, recirculation valves, chemical injection valves, etc., as is known in the art. The subbing injecting unit 135 provides an interface by which coil tubing 140 may be connected for performing various well intervention activities. A work vessel 145 positioned on the sea surface proximate the well 110 employs a coil tubing guide system 150 coupled to the LRP 138 to allow the coil tubing 140 to be extended down to the well 110 and interface with the LIP 125 through the guide 130. A surface injector unit 152 may be provided to insert and/or withdraw the coli tubing 140 from the coil tubing guide system 150.

The subsea Christmas tree 120 and lightweight intervention package (LIP) 125 are intended to be representative in nature. That is, they are intended to encompass any of a variety of different structures that may be operatively coupled to the well 110. For example, the subsea Christmas tree 120 typically comprises a plurality of valves that are used in controlling the production from the well 110. The subsea Christmas tree 120 may be of any desired shape or configuration (e.g., horizontal, vertical, etc.). Similarly, the LIP 125 is intended to generically represent any type of equipment that may be operatively coupled to the well 110 during an intervention process. It should be understood that FIG. 1 is also representative in that additional components, e.g., a tubing head, or flow spools to ancillary equipment, etc. may be positioned between some of the components depicted in FIG. 1. For example, a tubing head (not shown) may be positioned between the subsea well 110 and the subsea Christmas tree 120. Other items of subsea equipment may be operatively coupled to the well 110 in a variety of different configurations. Also, for ease of illustration, not all of the components of the subsea hydrocarbon production system 100 are illustrated. For example, production piping is not illustrated. Also, an umbilical extending from the work vessel 145 or some other location may interface with the Christmas tree 120. Thus, the illustrative equipment depicted in FIG. 1, and the arrangement thereof, should not be considered a limitation of the present subject matter.

The coil tubing guide system 150 includes a plurality of bend restrictor members 155 coupled to a return line 160. An upper guide member 165 is also provided to aid in aligning the coil tubing 140 with a channel (shown in FIG. 2) defined by the bend restrictor members 155. The upper guide member 165 may be coupled to the work vessel 145 (e.g., by four lines attached to corners of the upper guide member 165) to allow support the coil tubing guide system 150 and control the tensioning thereof. The return line 160 may be coupled to the LRP 138 to provide a return flow path for the coil tubing 140.

The coil tubing guide system 150 may be connected to the LIP 125 using various techniques. In one embodiment, a winch line (not shown), sheaved at the LRP 138 may be used to pull the coil tubing guide system 150 down to the subsea well 110. Using this arrangement, the coil tubing guide system 150 may be assembled to the appropriate length and towed behind the work vessel 145 to the site of the subsea well 110. The winching system may guide a connector on the LRP 138 into engagement with a corresponding connector on an end of the return line 160. Alternatively, a remotely operated vehicle (ROV) may be used to complete the engagement.

FIGS. 2 and 3 illustrate side and cross section views of the bend restrictor members 155, respectively. Each bend restrictor member 155 includes first and second members 200, 205 coupled to one another (e.g., by bolts 217, clamps (not shown), bands (not shown) etc.). The bend restrictor member 155 defines a coil tubing channel 210, a return line channel 215, and a pin recess 220. Pins 225 may be disposed within the pin recesses 220 to limit the rotation of adjacent bend restrictor members 155 with respect to one another to keep the coil tubing channel 210 aligned along the length of the coil tubing guide system 150. Generally, the fit between the pins 225 and the associated pin recesses 220 is relatively loose to allow some bending of the coil tubing guide system 150. In the illustrated embodiment, the ends 230 of the coil tubing channel 210 within each bend restrictor member 155 are beveled to allow a small amount of rotational misalignment and/or bending of the coil tubing guide system 150 without compromising the ability of the coil tubing guide system 150 to receive the coil tubing 140. In the illustrated embodiment, the bend restrictor members 155 are formed using a buoyant material, such as rigid syntactic foam. Other techniques for achieving buoyancy may also be used. For example, a sealed cavity construction may be used, wherein each half 200, 205 of the bend restrictor member 155 includes one or more sealed cavities.

The assembly process for the coil tubing guide system 150 includes providing a return line of a length appropriate for reaching the well 110. In the illustrated embodiment, the return line 160 is a flexible pipe, such as COFLON flexible pipe offered by Technip headquartered in Paris, France, or a different flexible pipe that may meet the standards set forth in API 17 B and API 17 J issued by the American Petroleum Institute under the titles “Recommended Practice for Flexible Pipe” and “Specification for Unbonded Flexible Pipe”. The individual members 200, 205 that make up each bend restrictor member 155 are positioned along the length of the return line 160. The pins 225 may be placed within the pin recesses 220 to align the coil tubing channel 210. Generally, the maximum bend radius of the coil tubing guide system 150 may be controlled based on the length and diameter of the bend restrictor members 155, the dimensions of the channels 210, 215, and the spacing between adjacent bend restrictor members 155. The size of the bend restrictor members 155 and the relative sizes of the coil tubing channel 210 and return line channel 215 may be selected to accommodate any size return line 160 and or coil tubing 140. The bend restrictor dimensions, channel dimensions, and/or spacing may be varied along the length of the coil tubing guide system 150 to provide different shapes in the water column (i.e., different maximum bend radii at different places). The maximum bend radii is also selected to provide a geometry that prevents compressive buckling of the coil tubing 140 is it is inserted into the LIP 125, subsea Christmas tree 120, and subsea well 110. Hence, the maximum bend radius is typically less than a buckling radius of the coil tubing 140, which may vary depending factors such as the material, wall thickness, radius, etc., of the coil tubing 140.

Generally, the materials selected for the bend restrictor members 155 provide an overall density that is less than seawater (i.e., <64 lb/ft³). Due to this characteristic, bend restrictor members 155 provide sufficient buoyancy to fully support their weight and the weight of the return line 160 with some residual buoyancy to provide some hydrodynamic stability in the water column between the work vessel 145 and the subsea Christmas tree 120. The work vessel 145 and associated tension control equipment need only support the fluid column weight present in the return line 160.

In the illustrated embodiment, the return line channel 215 is sized such that it is slightly smaller than the outside diameter of the return line 160 to provide an interference fit. Ribs (not shown) may be provided in one or more positions along the return line channel 215 to enhance the fit. Alternatively, other retention techniques may be used to retain the bend restrictor members 155 in the proper position, such as clamps (not shown) positioned between bend restrictor members 155. In such an embodiment, the clamps (not shown) may also be adapted to perform the anti-rotational functions of the pins 225. In some embodiments, the return line channel 215 may also be sized and shaped to support other lines, such as strength members (e.g., rope), electrical, umbilical, or chemical injection lines bundled with the return line 160.

After the coil tubing guide system 150 has been assembled and installed beneath the vessel 145, the buoyancy helps keep the coil tubing guide system 150 upright and the alignment provides a simple pathway for the coil tubing 145 to travel the length of the water column down to the subsea well 110. Because the coil tubing 140 is structurally supported and enclosed by the bend restrictor members 155, the coil tubing 140 is protected from damaging environmental loads. The coil tubing 140 follows the coil tubing channels 210 of the bend restrictor members 155 to the guide member 130, which directs the coil tubing 140 to the snubbing injecting unit 135. Because the coil tubing guide system 150 is not pressure or fluid containing ram equipment is not required at the surface. As seen in FIG. 1, a gap 170 may be provided between the lowest bend restrictor member 155 and the guide 130 to allow a remotely operated vehicle (ROV) to catch, retrieve, and change out tools or otherwise access the end of the coil tubing 140 without having to pull the end back to the surface. At the top end of the riser, the upper guide member 165 provides rough access to the coil tubing guide system 150, and the channels 210, 215. The upper guide member 165 is suspended from two or more guide lines 175, which provide a means to center the upper guide member 165 under the surface injecting unit 152 and provide in some modes additional top tension to the coiled tubing guide system 150 to augment the hydrodynamic stability of the coiled tubing guide system 150 in the water and support the fluid column weight of the circulated return fluids coming back up from the well 110 through the return line 160.

Referring to FIG. 4, a simplified diagram of the light intervention package (LIP) 125 is provided. In general, the LIP 125 is modular to allow various types of well interventions. For example, the lower riser package (LRP) 138 may include a production bore access port 400, a chemical injection port 410, and a return line port 420 that may be operable to interface with a variety of intervention tools. The LRP 138 typically includes wire cutting/sealing valves (or other sealing devices), crossover/circulation valves, recirculation valves, chemical injection valves, etc., as is known in the art. For clarity and to avoid obscuring the present subject matter, the construction of the LRP 138 is not described in detail herein.

The snubbing injecting unit 135 includes a snubber element 430 for sealing around the coil tubing 140 and an injecting unit 440 for applying motive force on the coil tubing to provide for inserting or ejecting the coil tubing 140. In general, the injecting unit 440 includes opposed endless belts that pass around rollers that are hydraulically or electromagnetically driven to move the coil tubing 140. The snubbing injecting unit 135 may also include a chemical injection recirculation valve 450 to allow various chemicals to be introduced into the well or for flushing the snubbing injecting unit 135.

Depending on the particular type of intervention, the equipment attached to the LRP 138 may be varied. For example, for a wireline intervention a lubricator may be coupled to the LRP 138 to allow a wireline tool to interface with the LRP 138. The LRP 138 may also be used to connect to a full completion workover riser. If the intervention type is changed, the LIP 125 may be readily configured to receive a different type of interface, such as the snubbing injecting unit 135.

The injecting unit 440 may be configured to operate in concert with the surface injecting unit 152 to maintain proper tension in the coil tubing 140. During an emergency disconnect event, cutting valves in the LRP 138 may shear the coil tubing, and the injecting unit 440 may eject the coil tubing 140 regardless of whether the coil tubing 140 is in compression or tension prior to the cutting to allow isolation valves in the LRP 138 to provide the pressure boundary for isolating the subsea well 110. An isolation valve may also be provided in the LRP 138 for isolating the return line port 420.

The coil tubing guide system 150 described herein provides numerous advantages. The bend restrictor members 155 provide lateral stability within the coil tubing channel 210 to keep the coil tubing 140 from buckling. The coil tubing channel 210 and its tapered ends 230 may be coated or sleeved with a lower friction, wear resistant material to augment of conveyance of the coil tubing 140 through the channel 210, 230 and lessen the possibility of damage to the bend restrictor members 155. Also, the bend ratio of the coil tubing guide system 150 may be varied depending on the size and placement of the bend restrictor members 155. The coil tubing guide system 150 eliminates the need for specialized high pressure containing piping seen in concentric risers. The elimination of the high pressure piping also eliminates the need for surface rams and/or snubbing units. The gaps in the coil tubing guide system 150 between the bend restrictor members 155 allow sea water surrounding the coil tubing to circulate and enter/leave the coil tubing channel 210 anywhere along the length of the coil tubing guide system 150, eliminating the phenomenon where circulated fluid coming back from the well 110 follows the movement of the coil tubing 140. The buoyancy of the coil tubing guide system 150 greatly reduces the weight supported by the work vessel 145. The modular nature of the bend restrictor members 155 and return line 160 provides for easy and cost-effective maintenance, as only broken or worn parts need to be replaced. Also, the coil tubing guide system 150 is separate from the coil tubing 140, allowing the appropriate size, strength, and pressure ratings for the coil tubing 140 to be varied for the particular intervention.

The particular embodiments disclosed above are illustrative only, as the disclosed subject matter may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the disclosed subject matter. Accordingly, the protection sought herein is as set forth in the claims below. 

1. A guide system, comprising: a flexible pipe; a plurality of bend restrictor members disposed along the flexible pipe and defining a first channel, the bend restrictor members being operable to limit a degree of bending present in the first channel.
 2. The system of claim 1, wherein each bend restrictor member defines a second channel for receiving the flexible pipe.
 3. The system of claim 2, wherein a diameter of the second channel is less than an outside diameter of the flexible pipe.
 4. The system of claim 1, wherein each bend restrictor member comprises first and second members cooperating to define the first channel.
 5. The system of claim 4, wherein the first and second members are bolted to one another.
 6. The system of claim 1, further comprising: a pin recess defined in each of two adjacent bend restrictor members; and a pin disposed in the pin recesses to limit a degree of rotation present between the adjacent bend restrictor members.
 7. The system of claim 1, wherein a segment of the first channel is defined by each bend restrictor member, and the segment defines at least one beveled end portion.
 8. The system of claim 1, wherein each bend restrictor member has an overall displacement volume to weight ratio which is less than sea water to create positive buoyancy.
 9. The system of claim 1, wherein at least one of the bend restrictor members comprises rigid syntactic foam.
 10. The system of claim 1, wherein at least one of the bend restrictor members comprises a molded member having at least one sealed cavity defined therein.
 11. The system of claim 1, wherein the degree of bending is limited by at least one of a dimension of one of the bend restrictor members, a dimension of the first channel, or the spacing between two adjacent bend restrictor members.
 12. The system of claim 11, wherein at least one of the bend restrictor dimension, the first channel dimension, or the spacing is varied to provide different maximum bend radii at corresponding portions of the guide system.
 13. The system of claim 1, wherein the first channel is lined with a material different than a material of the bend restrictor members.
 14. An apparatus for interfacing with a subsea well, comprising: a flexible pipe extending from a surface vessel to the subsea well; a plurality of bend restrictor members disposed along the flexible pipe and defining a first channel, the bend restrictor members being operable to limit a degree of bending present in the first channel; coil tubing extending from the surface vessel to the subsea well through the first channel.
 15. The apparatus of claim 14, further comprising a guide coupled to the surface vessel and operable to receive a first end of the coil tubing and guide the first end to the first channel during insertion of the coil tubing.
 16. The apparatus of claim 14, further comprising a lower riser package coupled to the subsea well and defining a production bore access port for accessing the subsea well and a return port, wherein the flexible pipe is coupled to the return port to provide a return circulation path to the surface vessel for the coil tubing.
 17. The apparatus of claim 16, further comprising a snubbing injection unit coupled to the lower riser package and in communication with the production bore access port and operable to receive the coil tubing, inject the coil tubing through the production bore access port, and provide a pressure retaining seal around the coil tubing.
 18. The apparatus of claim 16, further comprising a guide coupled to the snubbing injecting unit and operable to receive a first end of the coil tubing and guide the first end to the snubbing injecting unit during insertion of the coil tubing.
 19. The apparatus of claim 14, wherein each bend restrictor member defines a second channel for receiving the flexible pipe.
 20. The apparatus of claim 19, wherein a diameter of the second channel is less than an outside diameter of the flexible pipe.
 21. The apparatus of claim 14, wherein each bend restrictor member comprises first and second members cooperating to define the first channel.
 22. The apparatus of claim 21, wherein the first and second members are bolted to one another.
 23. The apparatus of claim 14, further comprising: a pin recess defined in each of two adjacent bend restrictor members; and a pin disposed in the pin recesses to limit a degree of rotation present between the adjacent bend restrictor members.
 24. The apparatus of claim 14, wherein a segment of the first channel is defined by each bend restrictor member, and the segment defines at least one beveled end portion.
 25. The apparatus of claim 14, wherein each bend restrictor member has an overall displacement volume to weight ratio which is less than sea water to create positive buoyancy.
 26. The apparatus of claim 14, wherein at least one of the bend restrictor members comprises rigid syntactic foam.
 27. The apparatus of claim 14, wherein at least one of the bend restrictor members comprises a molded member having at least one sealed cavity defined therein.
 28. The apparatus of claim 14, wherein the degree of bending is limited by at least one of a dimension of one of the bend restrictor members, a dimension of the first channel, or the spacing between two adjacent bend restrictor members.
 29. The apparatus of claim 28, wherein at least one of the bend restrictor dimension, the first channel dimension, or the spacing is varied to provide different maximum bend radii at corresponding portions of the guide system.
 30. The apparatus of claim 29, wherein the degree of bending is limited to a value less than a compressive buckling radius of the coil tubing.
 31. The apparatus of claim 14, wherein the first channel is lined with a material different than a material of the bend restrictor members.
 32. A method for interfacing with a subsea well, comprising: providing a plurality of bend restrictor members disposed along a flexible pipe and defining a first channel, the bend restrictor members being operable to limit a degree of bending present in the first channel; attaching the flexible pipe to the subsea well; inserting coil tubing from a surface vessel to the subsea well through the first channel to interface with the subsea well.
 33. The method of claim 32, further comprising providing a guide coupled to the surface vessel and operable to receive a first end of the coil tubing and guide the first end to the first channel during insertion of the coil tubing.
 34. The method of claim 32, further comprising coupling the flexible pipe to a lower riser package coupled to the subsea well, the lower riser package defining a production bore access port for accessing the subsea well and a return port, wherein the flexible pipe is coupled to the return port to provide a return circulation path to the surface vessel for the coil tubing.
 35. The method of claim 32, wherein each bend restrictor member comprises first and second members cooperating to define the first channel and a second channel, and the method further comprises: positioning the first and second members around the flexible pipe to enclose the flexible pipe in the second channel; and coupling the first and second members to one another.
 36. The method of claim 35, wherein a diameter of the second channel is less than an outside diameter of the flexible pipe.
 37. The method of claim 32, wherein a pin recess is defined in each of two adjacent bend restrictor members, and the method further comprises providing a pin in the pin recesses, the pin limiting a degree of rotation present between the adjacent bend restrictor members.
 38. The method of claim 32, wherein a segment of the first channel is defined by each bend restrictor member, and the segment defines at least one beveled end portion.
 39. The method of claim 32, wherein each bend restrictor member has an overall displacement volume to weight ratio which is less than sea water to create positive buoyancy. 